Permanent downhole deployment of optical sensors

ABSTRACT

The present invention involves methods and apparatus for permanent downhole deployment of optical sensors. Specifically, optical sensors may be permanently deployed within a wellbore using a casing string. In one aspect, one or more optical sensors are disposed on, in, or within the casing string. The optical sensors may be attached to an outer surface of the casing string or to an inner surface of the casing string, as well as embedded within a wall of the casing string. The optical sensors are capable of measuring wellbore parameters during wellbore operations, including completion, production, and intervention operations.

CROSS-REFERENCE TO RELATED APPLICATIONS

This application is a continuation-in-part of co-pending U.S. patentapplication Ser. No. 10/288,229, filed Nov. 5, 2002, which is hereinincorporated by reference in its entirety.

This application is related to co-pending U.S. patent application Ser.No. 10/677,135, filed on the same day as the current application,entitled “Instrumentation for a Downhole Deployment Valve”, which isherein incorporated by reference in its entirety.

BACKGROUND OF THE INVENTION

1. Field of the Invention

The present invention generally relates to methods and apparatus for usein oil and gas wellbores. More particularly, the invention relates tousing instrumentation to monitor downhole conditions within wellbores.

2. Description of the Related Art

In well completion operations, a wellbore is formed to accesshydrocarbon-bearing formations by the use of drilling. Drilling isaccomplished by utilizing a drill bit that is mounted on the end of adrill support member, commonly known as a drill string. To drill withinthe wellbore to a predetermined depth, the drill string is often rotatedby a top drive or rotary table on a surface platform or rig, or by adownhole motor mounted towards the lower end of the drill string. Afterdrilling to a predetermined depth, the drill string and drill bit areremoved and a section of casing is lowered into the wellbore. An annulararea is thus formed between the string of casing and the formation. Thecasing string is temporarily hung from the surface of the well. Acementing operation may optionally be conducted in order to fill theannular area with cement and set the casing string within the wellbore.Using apparatus known in the art, the casing string may be cemented intothe wellbore by circulating cement into the annular area defined betweenthe outer wall of the casing and the borehole. The amount and extent ofcement in the annular area may vary from a small amount of cement onlyat the lower portion of the annulus to a large amount of cementextending to the surface or the top of the casing string. Thecombination of cement and casing strengthens the wellbore andfacilitates the isolation of certain areas of the formation behind thecasing for the production of hydrocarbons.

It is common to employ more than one string of casing in a wellbore. Inthis respect, the well is drilled to a first designated depth with adrill bit on a drill string. The drill string is removed. A first stringof casing or conductor pipe is then run into the wellbore and set in thedrilled out portion of the wellbore, and cement may be circulated intothe annulus behind the casing string. Next, the well is drilled to asecond designated depth, and a second string of casing, or liner, is runinto the drilled out portion of the wellbore. The second string is setat a depth such that the upper portion of the second string of casingoverlaps the lower portion of the first string of casing. The secondliner string is then fixed, or “hung” off of the existing casing by theuse of slips which utilize slip members and cones to wedgingly fix thenew string of liner in the wellbore. The second casing string may thenbe cemented. This process is typically repeated with additional casingstrings until the well has been drilled to total depth. As more casingstrings are set in the wellbore, the casing strings become progressivelysmaller in diameter in order to fit within the previous casing string.In this manner, wells are typically formed with two or more strings ofcasing of an ever-decreasing diameter.

As an alternative to the conventional method, drilling with casing is amethod increasingly used to place casing strings of decreasing diameterwithin the wellbore. This method involves attaching a cutting structurein the form of a drill bit to the same string of casing which will linethe wellbore. Rather than running a drill bit on a smaller diameterdrill string, the drill bit or drill shoe is run in at the end of thelarger diameter of casing that will remain in the wellbore and may becemented therein. Drilling with casing is often the preferred method ofwell completion because only one run-in of the working string into thewellbore is necessary to form and line the wellbore.

While drilling the drill string or the casing string into the formation,drilling fluid is ordinarily circulated through the inner diameter ofthe casing string or drill string, out through the casing string ordrill string, and up around the outer diameter of the casing string ordrill string. Typically, passages are formed through the drill bit toallow circulation of the drill fluid. Fluid circulation preventscollapse of the formation around the drill string or casing string,forces the cuttings produced by the drill bit drilling through theformation out from the wellbore and up to the surface rather thanallowing the cuttings to enter the inner diameter of the drill string orcasing string, and facilitates the drilling process by forming a paththrough the formation for the drill bit.

Recent developments have allowed sensing of parameters within thewellbore and within the formation during the life of a producing well.Typically, the drill string or casing string with the drill bit attachedthereto is drilled into the formation to a depth. When drilling with thedrill string, the drill string is removed, a casing string is placedwithin the drilled-out wellbore, and the casing string may be cementedinto the wellbore. When drilling with casing, the casing string may becemented into place once it has drilled to the desired depth within theformation. Production tubing is then inserted into the casing string,and perforations are placed through the production tubing, casingstring, cement around the casing string, and the formation at thedesired depth for production of hydrocarbons. The production tubing mayhave sensors therearound for sensing wellbore and formation parameterswhile drilling and during production operations.

Historically, monitoring systems have used electronic components toprovide pressure, temperature, flow rate and water fraction on areal-time basis. These monitoring systems employ temperature gauges,pressure gauges, acoustic sensors, seismic sensors, electromagneticsensors, and other instruments or “sondes”, including those whichprovide nuclear measurements, disposed within the wellbore. Suchinstruments are either battery operated, or are powered by electricalcables deployed from the surface. The monitoring systems havehistorically been configured to provide an electrical line that allowsthe measuring instruments, or sensors, to send measurements to thesurface.

Recently, optical sensors have been developed which communicate readingsfrom the wellbore to optical signal processing equipment located at thesurface. Optical sensors may be disposed along the production tubingwithin a wellbore. An optical line or cable is run from the surface tothe optical sensor downhole. The optical sensor may be a pressure gauge,temperature gauge, acoustic sensor, seismic sensor, or other sonde. Theoptical line transmits optical signals to the optical signal processorat the surface.

The optical signal processing equipment includes an excitation lightsource. Excitation light may be provided by a broadband light source,such as a light emitting diode (LED) located within the optical signalprocessing equipment. The optical signal processing equipment alsoincludes appropriate equipment for delivery of signal light to thesensor(s), e.g., Bragg gratings or lasers and couplers which split thesignal light into more than one leg for delivery to more than onesensor. Additionally, the optical signal processing equipment includesappropriate optical signal analysis equipment for analyzing the returnsignals from the Bragg gratings.

The optical line is typically designed so as to deliver pulses orcontinuous signals of optic energy from the light source to the opticalsensor(s). The optical cable is also often designed to withstand thehigh temperatures and pressures prevailing within a hydrocarbonwellbore. Preferably, the optical cable includes an internal opticalfiber which is protected from mechanical and environmental damage by asurrounding capillary tube. The capillary tube is made of a highstrength, rigid-walled, corrosion-resistant material, such as stainlesssteel. The tube is attached to the sensor by appropriate means, such asthreads, a weld, or other suitable method. The optical fiber contains alight guiding core which guides light along the fiber. The corepreferably employs one or more Bragg gratings to act as a resonantcavity and to also interact with the sonde.

While optical sensors placed on production tubing allow measurementswhile the production tubing is located within the wellbore, the sensorson production tubing do not allow monitoring of wellbore and formationconditions during the drilling and well completion operations and afterthe production tubing is removed from the wellbore. Thus, the sensorsare only deployed temporarily while the production tubing is within thewellbore. Furthermore, when employing seismic sensors which need to becoupled to the formation, sensors located on production tubing arelocated at a distance from the formation, so that measurements offormation parameters derive some inaccuracy due to signal attenuation ofthe sensor without coupling the sensor to the formation. Coupling thesensors to the formation requires complicated maneuvers and equipmentacross the distance between the production tubing and the formation.

Accordingly, there is a need for apparatus and methods for permanentlydeploying measurement devices. There is a need for apparatus and methodsfor measuring wellbore and formation conditions throughout drilling andwell completion operations, well production operations, and theremaining operations of a well. Furthermore, there is a need forapparatus and methods for locating measurement devices closer to theformation than is currently possible to increase the accuracy of themeasured parameters and to facilitate coupling of the optical sensors tothe formation.

SUMMARY OF THE INVENTION

In one aspect, the present invention involves an apparatus forpermanently measuring wellbore or formation parameters, comprising acasing string permanently located within a wellbore, and at least oneoptical sensor attached to the casing string, the at least one opticalsensor capable of measuring one or more wellbore or formationparameters. In another aspect, the present invention provides anapparatus for permanently measuring wellbore or formation parameters,comprising a casing string permanently located within a wellbore, and atleast one optical sensor located at least partially within a wall of thecasing string, the at least one optical sensor capable of measuring oneor more wellbore or formation parameters.

In yet another aspect, the present invention provides a method ofpermanently monitoring wellbore or formation parameters, comprisingproviding a casing string having at least one optical sensor attachedthereto, locating the casing string within a wellbore, and measuring oneor more wellbore or formation parameters with the at least one opticalsensor.

In another aspect, the present invention includes an apparatus formeasuring fluid flow through a casing string, comprising a casing stringpermanently located within a wellbore, one or more optical sensorsattached to the casing string for measuring parameters of a fluidflowing through the casing string, and control circuitry and signalprocessing adapted to determine a composition of the fluid or flow rateof the fluid based on one or more signals received from the one or moreoptical sensors. In yet another aspect, the present invention includes amethod for determining a flow rate or one or more volumetric fractionsof individual phases of a fluid flowing through a casing string,comprising locating a casing string having one or more optical sensorsattached thereto within a wellbore, measuring one or more parameters ofthe fluid flowing through the casing string with the one or more opticalsensors, and using the one or more parameters to determine the flow rateof the fluid or one or more volumetric fractions of the fluid.

BRIEF DESCRIPTION OF THE DRAWINGS

So that the manner in which the above recited features of the presentinvention can be understood in detail, a more particular description ofthe invention, briefly summarized above, may be had by reference toembodiments, some of which are illustrated in the appended drawings. Itis to be noted, however, that the appended drawings illustrate onlytypical embodiments of this invention and are therefore not to beconsidered limiting of its scope, for the invention may admit to otherequally effective embodiments.

FIG. 1 is a cross-sectional view of a casing string within a wellbore.An optical sensor is permanently deployed on an outer surface of thecasing string through attachment of a sensor protector to the outersurface of the casing string, the optical sensor being housed within thesensor protector.

FIG. 2 is a cross-sectional view of a casing string within a wellbore.An optical sensor is housed within a protective pocket on a mandrel. Themandrel is located in the casing string.

FIG. 3 is a cross-sectional view of a casing string within a wellbore.An optical sensor is embedded within a wall of the casing string.

FIG. 4 is a cross-sectional view of a casing string within a wellbore.An optical sensor is permanently deployed with the casing string throughthe attachment of a sensor protector to an inner surface of the casingstring, the optical sensor housed within the sensor protector.

FIG. 5 is a cross-sectional view of a casing string within a wellbore.An optical sensor is attached directly to the outer surface of thecasing string.

FIG. 6 is a cross-sectional view of a flow meter disposed in a casingstring, the casing string located within a wellbore. The flow meter ispermanently deployed within the wellbore on the casing string.

FIG. 7 is a cross-sectional view of a flow meter disposed within acasing string, the casing string having an earth removal memberoperatively attached to its lower end. The casing string is showndrilling into the formation.

DETAILED DESCRIPTION OF THE PREFERRED EMBODIMENT

In contrast to the current practice of deploying sensors duringproduction operations with production tubing, the present inventionprovides apparatus and methods for permanently deploying optical sensorsfor use in measuring wellbore parameters during all wellbore operations,including but not limited to completion operations, drilling operations,and intervention operations. The present invention also beneficiallyprovides methods and apparatus for placing optical sensors within thewellbore earlier in the wellbore operations, specifically duringdrilling and completion of the well, which occur prior to productionoperations. Additionally, the present invention includes apparatus andmethods for locating seismic sensors closer to the formation than ispossible with the current use of production tubing for the deployment ofoptical sensors, by use of one or more optical sensors deployed with acasing string. Although pressure and temperature sensing does notrequire coupling of the optical sensor to the formation, a seismicsensor (e.g. an accelerometer or geophone) must be coupled to theformation by either cementing the seismic sensor into place or byplacing the sensor into significant contact with the formation. Thepresent invention facilitates coupling of seismic optical sensors to theformation, thereby increasing accuracy of the seismic readings.

As used herein, an “optical sensor” may comprise any suitable type ofoptical sensing elements, such as those described in U.S. Pat. No.6,422,084, entitled “Bragg Grating Pressure Sensor”, which is hereinincorporated by reference in its entirety. For example, the opticalsensor may comprise an optical fiber, having the reflective elementembedded therein; and a tube, having the optical fiber and thereflective element encased therein along a longitudinal axis of thetube, the tube being fused to at least a portion of the fiber.Alternatively, the optical sensor may comprise a large diameter opticalwaveguide having an outer cladding and an inner core disposed therein.

Optical Sensor Deployment

FIGS. 1–7 show the various ways in which one or more optical sensors maybe permanently deployed on casing. One or more optical sensors may bedeployed on the outside of the casing, as shown in FIGS. 1–2 and 5, ordeployed on the inside of the casing, as shown in FIG. 4. Alternatively,one or more optical sensors may be embedded within the casing, as shownin FIG. 3. One or more optical sensors may also be part of a flow meterdisposed in a casing string, as shown in FIGS. 6–7.

Exemplary Deployment Apparatus and Techniques

FIG. 1 shows an embodiment of the present invention. A casing string 5is shown within a wellbore 10 formed within a formation 15. The casingstring 5, which comprises one or more casing sections threadedlyconnected to one another, has an inner surface 6 and an outer surface 7.A physically alterable bonding material 20, preferably cement, may beutilized to permanently set the casing string 5 within the wellbore 10.

A sensor carrier 25 is attached to the outer surface 7 of the casingstring 5 and disposed circumferentially around the casing string 5.Within the sensor carrier 25 is an optical sensor 30, which is used tosense conditions such as temperature, pressure, acoustics, and/orseismic conditions, within the wellbore 10 and the formation 15. Thesensor carrier 25 attaches the optical sensor 30 to the outer surface 7of the casing string 5, as well as protects the optical sensor 30 fromthe often harsh environment within the wellbore 10.

Optical sensors offer one alternative to conventional electronicsensors. Typically, optical sensors have no downhole electronics ormoving parts and, therefore, may be exposed to harsh downhole operatingconditions without the typical loss of performance exhibited byelectronic sensors. The optical sensor 30 may utilize strain-sensitiveBragg gratings (not shown) formed in a core of one or more opticalfibers (not shown) included in an optical cable 55. The optical cable 55is connected at one end to the optical sensor 30 and runs through thesensor carrier 25, alongside the outer surface 7 of the casing string 5,and to a surface 65 of the wellbore 10. Bragg grating-based sensors aresuitable for use in very hostile and remote environments, such as founddownhole in wellbores.

Depending on a specific arrangement, multiple optical sensors 30 may beemployed, attached to the outer surface 7 by multiple sensor carriers25, so that the optical sensors 30 may be distributed on a common one ofthe fibers or distributed among multiple fibers. Additionally, thefibers may be encased in protective coatings, and may be deployed infiber delivery equipment, as is well known in the art.

The one or more sensor carrier(s) 25 may be attached to the outersurface 7 by any method known by those skilled in the art in which theone or more sensor carrier(s) 25 provides adequate protection to the oneor more optical sensor(s) 30 and effectively attaches the one or moreoptical sensor(s) to the outer surface 7. In one embodiment, the sensorcarrier 25 is welded to the outer surface 7. In another embodiment, thesensor carrier 25 is clamped firmly to the outer surface 7 of the casingstring 5 and may be cemented into place.

Disposed at a surface 65 of the wellbore 10 is a wellhead 50 throughwhich the casing string 5 and other tools and components used duringwellbore operations are lowered into the wellbore 10. Also located atthe surface 65 is a signal interface 60. The optical cable 55 isconnected to the signal interface 60 at the opposite end from itsconnection to the optical sensor 30.

The signal interface 60 may include a broadband light source, such as alight emitting diode (LED), and appropriate equipment for delivery ofsignal light to the Bragg gratings formed within the core of the opticalfibers. The signal interface 60 may further include logic circuitry,which encompasses any suitable circuitry and processing equipmentnecessary to perform operations described herein, including appropriateoptical signal processing equipment for receiving and/or analyzing thereturn signals (reflected light) from the one or more optical sensors 30transmitted via the one or more optical cables 55. For example, thelogic circuitry may include any combination of dedicated processors,dedicated computers, embedded controllers, general purpose computers,programmable logic controllers, and the like. Accordingly, the logiccircuitry may be configured to perform operations described herein bystandard programming means (e.g., executable software and/or firmware).

Below the optical sensor 30, the fibers may be connected to othersensors (not shown) disposed along the casing string 5, terminated, orconnected back to the signal interface 60. While not shown, the one ormore cables 55 may also include any suitable combination of peripheralelements (e.g., optical cable connectors, splitters, etc.) well known inthe art for coupling the fibers.

The one or more optical sensors 30 may include pressure, temperature,acoustic, seismic, velocity, or speed of sound sensors, or any othersuitable sensors for measuring the desired parameters within thewellbore 10 or the formation 15. The pressure and temperature (P/T)sensors may be similar to those described in detail in commonly-ownedU.S. Pat. No. 5,892,860, entitled “Multi-Parameter Fiber Optic SensorFor Use In Harsh Environments”, issued Apr. 6, 1999 and incorporatedherein by reference in its entirety. When using a velocity sensor 103 orspeed of sound sensor, the optical sensor 30 may be similar to thosedescribed in commonly-owned U.S. Pat. No. 6,354,147, entitled “FluidParameter Measurement in Pipes Using Acoustic Pressures”, issued Mar.12, 2002 and incorporated herein by reference in its entirety. Whenusing a seismic sensor or acoustic sensor, the optical sensor 30 may besimilar to the Bragg grating sensor described in commonly-owned U.S.Pat. No. 6,072,567, entitled “Vertical Seismic Profiling System HavingVertical Seismic Profiling Optical Signal Processing Equipment and FiberBragg Grafting Optical Sensors”, issued Jun. 6, 2000, which is hereinincorporated by reference in its entirety.

FIG. 2 depicts an alternate embodiment of the present invention. Acasing string 105 includes individual mandrels or casing sections 105A,105B, and 105C, which are preferably threadedly connected to oneanother. The casing string 105 may include three casing sections 105A–C,as shown, or may include any other number of casing sections threadedlyconnected to one another. Alternatively, one casing section 105B mayconstitute an embodiment of the present invention. The casing string 105has an inner surface 106 and an outer surface 107.

The casing string 105 is disposed within a wellbore 110 located within aformation 115. A physically alterable bonding material 120, preferablycement, may be disposed around the outer surface 107 of the casingstring 105 to set the casing string 105 within the wellbore 110. Thephysically alterable bonding material 120 is set in an annulus betweenthe outer surface 107 and an inner diameter of the wellbore 110.

At a surface 165 of the wellbore 110 is a wellhead 150. Also at thesurface 165 is a signal interface 160, to which an optical cable 155 isconnected. The signal interface 160, optical cable 155, and wellhead 150include substantially the same components and perform substantially thesame functions as the signal interface 60, optical cable 55, andwellhead 50 of FIG. 1, so the above discussion regarding thesecomponents of FIG. 1 applies equally to the components of FIG. 2.

One or more of the casing sections 105A–C include one or more protectivepockets 111 around the outer surface 107 of the casing sections 105A, B,and/or C. Alternatively, although not shown, the one or more protectivepockets 111 may be located around the inner surface 106 of the casingsections 105A, B, and/or C. FIG. 2 shows a protective pocket 111disposed around the outer surface 107 of the casing section 105B. Theprotective pocket 111 is a tubular-shaped mandrel which is preferablybuilt into the casing section 105B, so that the casing section 105B mayconveniently be placed within the casing string 105 by threadedconnection and thus made readily usable. The protective pocket 111 maybe welded at the connection points to the outer surface 107 of thecasing section 105B. In an alternate method of attachment to the casingsection 105B, the protective pocket 111 may be threaded onto the outersurface 107 of the casing section 105B.

Housed within the protective pocket 111 is at least one optical sensor130, which is disposed around the outer surface 107 of the casing string105. The optical sensor 130 performs substantially the same functions,has substantially the same characteristics, and is configured insubstantially the same manner as the optical sensor 30 described abovein relation to FIG. 1; therefore, the above discussion regarding theoptical sensor 30 applies equally to the optical sensor 130. The opticalcable 155 connects the optical sensor 130 to the signal interface 160 tocommunicate information gathered from within the wellbore 110 and/or theformation 115 from the optical sensor 155 to the signal interface 160,as well as to transmit signals from the light source located within thesignal interface 160 to the optical sensor 130. To connect the opticalsensor 130 to the signal interface 160, the optical cable 155 runsthrough the protective pocket 111 at a predetermined location.

An alternate embodiment of the present invention is shown in FIG. 3. Acasing string 205, which may include one or more casing sectionsthreadedly connected to one another, is disposed within a wellbore 210located within a formation 215. The casing string 205 may be set withinthe wellbore 210 using a physically alterable bonding material 220 asdescribed above in relation to FIG. 1. The casing string 205 has aninner surface 206 and an outer surface 207.

A wellhead 250 located at a surface 265 of the wellbore 210, a signalinterface 260, and an optical cable 255 are substantially similar inconfiguration, operation, and function to the wellhead 50, signalinterface 60, and optical cable 55 described above in relation to FIG.1; accordingly, the above discussion applies equally to the wellhead250, signal interface 260, and optical cable 255 of FIG. 3. However, anoptical cable 255 of FIG. 3 runs through a wall of the casing string205, between the inner surface 206 and the outer surface 207 of thecasing string 205, rather than outside the outer surface 207 of thecasing string as depicted in FIG. 1.

In the embodiment shown in FIG. 3, an optical sensor 230 is at leastpartially embedded within the wall of the casing string 205 between theinner surface 206 and the outer surface 207 of the casing string 205.The optical sensor 230 as well as the optical cable 255 may be placedwithin the wall of the casing string 205 when the casing string 205 isconstructed. A casing section may house the optical sensor 230 withinits wall, so that the casing section may be readily threadedly connectedto other casing sections which may or may not have optical sensors 230located therein, to form the casing string 205. The optical sensor 230is substantially the same as the optical sensor 30, so that the abovediscussion applies equally to the optical sensor 230.

FIG. 4 shows a further alternate embodiment of the present inventionsimilar to FIG. 1, but with a different location of a sensor carrier325, optical sensor 330, and optical cable 355 in relation to the casingstring 305. As illustrated in FIG. 4, the sensor carrier 325 is attachedto the inner surface 306 of the casing string 305. The optical sensor330 is disposed within the sensor carrier 325, and thus disposed aroundthe inner surface 306 of the casing string 305. The optical cable 355may run from the optical sensor 330, through the wall of the casingstring 305, up by the outer surface 307 of the casing string 305, and tothe signal interface 360.

As described above, the sensor carrier 325 may be welded to the innersurface 306 of the casing string 305, or in the alternative, clampedfirmly onto the inner surface 306. The sensor carrier 325 protects theoptical sensor 330 within its housing from conditions within thewellbore 310, as well as attaches the optical sensor 330 to the casingstring 305.

Another embodiment of the present invention is illustrated in FIG. 5,including a casing string 405 with an inner surface 406 and an outersurface 407, and an optical sensor 430 attached to the outer surface407. In this embodiment, there is no sensor carrier 25 as in theembodiment of FIG. 1. The optical sensor 430 is welded or firmly clampeddirectly to the outer surface 407 of the casing string 405. The casingstring 405 with the optical sensor 430 attached to its outer surface 407may be permanently set within the wellbore 410 with the physicallyalterable bonding material 420, preferably cement.

Although not depicted, the optical sensor 430 may be directly attachedto the inner surface 406 in the same way as described above in relationto its attachment to the outer surface 407. In this embodiment, theoptical cable 455 may be routed from the optical sensor 430 through thecasing string 405 and alongside the outer surface 407 of the casingstring 405 to the signal interface 460.

In the above embodiments, the physically alterable bonding material 420may be used to couple the optical sensor(s) 430 (when employing seismicsensors) to the formation 415 to allow sensing of formation parameters.In the alternative, the seismic sensors may be coupled to the formation415 by significant contact with the formation 415. Thus, the aboveembodiments are advantageous relative to the prior art production stringdeployed seismic sensors, which involved complicated and tenuouscoupling of the sensors to the formation from the production tubing.Also in the above embodiments, any number of optical sensors 30, 130,230, 330, 430 may be disposed along the casing string 5, 105, 205, 305,405, in any combination of attachment by one or more sensor carriers 25,325, attachment by one or more protective pockets 111, embedding withinthe casing string 205 wall, and/or attachment directly to the casingstring 405. Further, any combination of types of optical sensors 30,130, 230, 330, 430, including but not limited to pressure sensors,temperature sensors, acoustic sensors, and seismic sensors, may be usedalong the casing string 5, 105, 205, 305, 405 and connected to thesignal interface 60, 160, 260, 360, 460 by a common optical cable 55,155, 255, 355, 455 or by multiple optical cables running from eachoptical sensor 30, 130, 230, 330, 430. In the embodiments involving thesensor carriers 25, 325 and the protective pocket 111, any number ofoptical sensors 30, 330, or 130 may be present within the sensor carrier25, 325 and/or the protective pocket 111.

The operation of any or all of the embodiments of FIGS. 1–5 will bedescribed with the component numbers of FIG. 1, unless otherwiseindicated. Initially, one or more casing sections are threaded to oneanother to form the casing string 305. The casing sections may alreadyhave the sensor carrier 25 and/or the sensor carrier 325, the protectivepocket 111, the embedded optical sensor 230, and/or the optical sensor430 attached directly to them, as well as the optical sensor(s) 30, 230located within the sensor carrier(s) 25, 325 and/or protective pocket(s)111. Alternatively, the optical sensor(s) 30 may be attached after thecasing string 5 has been assembled from the casing sections. Theattachment of the sensor(s) 30, protective pocket(s) 111, and/or sensorcarrier(s) 25, 325 may be by welding, firmly clamping, threading ontothe casing string 5, or by any other method described above or known tothose skilled in the art. The one or more optical cable(s) 55 isconnected at one end to the one or more optical sensor(s) 30 and at theother end to the signal interface 60.

A drill string (not shown) having an earth removal member (not shown) atits lower end is utilized to drill into the formation 15 to a firstdepth. Alternatively, the casing string 5 may have an earth removalmember operatively connected to its lower end, and the casing string 5may be used to drill into the formation 15. In both cases, drillingfluid is circulated through the drill string or casing string 5 whiledrilling to wash particulate matter including cuttings from theformation 15 up to the surface 65. In the case of drilling with thedrill string, the drill string is retrieved to the surface 65, and thecasing string 5 is lowered into the drilled-out wellbore 10. Whendrilling with the casing string 5, the casing string 5 is alreadydisposed within the wellbore 10 and remains therein.

After the casing string 5 is located within the wellbore 10, thephysically alterable bonding material 20 may be introduced into theinner diameter of the casing string 5, to flow out through the lower endof the casing string 5, then up through an annulus between the outersurface 7 of the casing string 5 and the inner diameter of the wellbore10. The physically alterable bonding material 20 may be allowed to fillat least a portion of the annulus and to cure under hydrostaticconditions to permanently set the casing string 5 within the wellbore10. FIGS. 1–5 show the casing strings 5, 105, 205, 305, 405 cementedwithin the wellbore 10, 110, 210, 310, 410, the optical sensors 30, 130,230, 330, 430 therefore permanently deployed within the wellbore 10,110, 210, 310, 410 by use of the casing strings 5, 105, 205, 305, 405.

At this point, the optical sensor 30, when using a seismic sensor, iscoupled to the formation 15 and therefore is capable of sensingconditions within the formation 15. If the optical sensor 30 is apressure or temperature sensor, the light source within the signalinterface 60 may introduce a light signal into the optical cable 55.Then the optical sensor 30 may be used to transmit these wellboreparameters to the signal interface 60. The signal interface 60 is thenused to process the measured parameters into readable information. Inthe alternative, processing of wellbore or formation parameters intoreadable information may be accomplished off-site. After setting thecasing string 5 within the formation 15, the optical sensor 30 iscapable of measuring wellbore and formation parameters in real timeduring all subsequent operations, including further drilling andcompletion operations as well as production and intervention operations.

Seismic Sensing

If the optical sensor 30 is a seismic or acoustic sensor, source ofseismic energy (not shown) must be present to emit an acoustic orseismic wave into the formation 15. The seismic source may be active andcontrolled, may result from microseismic events that can occurnaturally, or may be induced by hydrocarbon fluid production-relatedeffects. The acoustic wave is then reflected or partially reflected fromthe formation 15 into the seismic sensor 30, which detects and measuresthe acoustic wave emitted by the seismic source. One or more seismicsources may emit one or more acoustic waves that are at least partiallyreflected at different locations within the formation 15 to measureconditions at multiple locations within the formation 15. Seismic dataobtained with the optical seismic sensor 30 can be used to directlyestimate rock properties, water saturation, and hydrocarbon content. Theoperation of an optical seismic sensor used while inserting a drillstring into a casing string (as well as while the drill string isstationary) and the measurements obtained with the optical sensor aredescribed in co-pending U.S. patent application Ser. No. 10/677,135,filed on the same day as the current application, entitled“Instrumentation for a Downhole Deployment Valve”, which is hereinincorporated by reference in its entirety.

The seismic source(s) may be located within the wellbore 10 such as in adrill string used to drill a wellbore of a second depth within theformation 15 (described below), or may be located at the surface 65 ofthe wellbore 10. Additionally or alternatively, the seismic source(s)may be located within a proximate wellbore (not shown). The vibration ofthe drill string itself during drilling a wellbore of a second depth(described below) against the casing string 5 or against the wellbore10, or the vibration of another tool within the wellbore 10, may alsoconstitute the seismic source(s). As described above, each seismicsource emits an acoustic wave into various locations with the formation15, then the acoustic wave at least partially reflects from thelocations in the formation 15 back to the seismic sensor 30, whichtransmits the formation 15 parameter to the signal interface 60 throughthe optical cable 55. Additionally, each of the seismic sources maytransmit an acoustic wave directly to the seismic sensor 30 forcalibration purposes to account for the time delay caused by reflectionfrom the formation 15. The direct transmission of the acoustic wave isnecessary to process the gathered information and interpret the finalimage by deriving the distance between the seismic source and theseismic sensor 30 plus the travel time.

In a specific application of the present invention, the seismic sourcemay be located on or within the drill string (not shown) used to drillto a second depth within the formation 15 to set a second casing string(not shown) in the formation 15 below the first casing string 5 or toaccess the formation 15 below the first casing string 5 (e.g., torecover hydrocarbon fluid from an open-hole wellbore drilled below thefirst casing string 5). The seismic source may be located on or in theearth removal member at the lower end of the drill string. In thealternative, the seismic source may constitute the vibration of thedrill string, earth removal member, and/or any other tool used indrilling into the formation 15 to a second depth.

In the above application, the drill string is lowered into the innerdiameter of the casing string 5 through and below the casing string 5.The drill string is then used to drill the wellbore to a second depthwithin the formation 15. Drilling fluid is circulated while the drillstring is lowered to the second depth. Because the seismic sensor 30 ispermanently located on, in, or within the casing string 5, formationparameters may be constantly measured and updated in real time whilelowering the drill string into the inner diameter of the casing string5, as well as while drilling with the drill string to the second depthwithin the formation 15.

If the seismic source is at the surface 65 or within a proximatewellbore, seismic conditions may be measured prior to as well as afterinsertion of the drill string into the wellbore 10, so that real timeformation conditions may be transmitted to the surface 65 throughacoustic waves emitted from the seismic source and at least partiallyreflected from the formation 15 at one or more locations to the seismicsensor 30, then through formation parameters transmitted through theoptical cable 55. Regardless of the location of the seismic source(s),the optical cable 55 is used to send the wellbore parameter measurementsto the signal interface 60. The signal interface 60 processes theinformation received through the optical cable 55. The operator may readthe information outputted by the processing unit and adjust the positionof the drill string during drilling, the composition of the drillingfluid used during drilling with the drill string, or any other parameterduring the life of the well. In the alternative, the data may beinterpreted off-site at a data processing center.

Any number of acoustic waves may be emitted by any number of seismicsources at any angle with respect to the formation 15 and to anylocation within the formation 15. Seismic measurements may be used inthe above embodiments to monitor the drilling-induced vibrations of thedrill string to possibly evaluate drilling conditions within theformation 15, such as wear of the earth removal member or drill bit,type of rock that makes up the formation 15, and/or smoothness ofdrilling.

Measuring Flow While Drilling

FIG. 6 shows another embodiment of the present invention. A flow meter575 is threadedly connected to casing sections above and/or below theflow meter 575 to form a casing string 505. The casing string 505, whichhas an inner surface 506 and an outer surface 507, is shown set within awellbore 510. The wellbore 510 has been drilled out of a formation 515.The casing string 505 may be set within the wellbore 510 by introducinga physically alterable bonding material 520, preferably cement, into anannulus between the outer surface 507 of the casing string 505 and theinner diameter of the wellbore 510, and allowing the physicallyalterable bonding material 520 to cure under hydrostatic conditions topermanently set the casing string 505 within the wellbore 510.

A wellhead 550 may be located at a surface 565 of the wellbore 510.Various tools, including the casing string 505 and a drill string 580(described below) may be lowered through the wellhead 550. A signalinterface 560 is also present at the surface 565. The signal interface560 may include a light source, delivery equipment, and logic circuitry,including optical signal processing, as described above in relation tothe signal interface 60 of FIG. 1. An optical cable 555, which issubstantially the same as the optical cable 55 described above inrelation to FIG. 1, is connected at one end to the signal interface 560.

The flow meter 875 may be substantially the same as the flow meterdescribed in co-pending U.S. patent application Ser. No. 10/348,040,entitled “Non-Intrusive Multiphase Flow Meter” and filed on Jan. 21,2003, which is herein incorporated by reference in its entirety. Otherflow meters may also be useful with the present invention. The flowmeter 575 allows volumetric fractions of individual phases of amultiphase mixture flowing through the casing string 505, as well asflow rates of individual phases of the multiphase mixture, to be found.The volumetric fractions are determined by using a mixture density andspeed of sound of the mixture. The mixture density may be determined bydirect measurement from a densitometer or based on a measured pressuredifference between two vertically displaced measurement points and ameasured bulk velocity of the mixture, as described in theabove-incorporated by reference patent application. Various equationsare utilized to calculate flow rate and/or component fractions of thefluid flowing through the casing string 505 using the above parameters,as disclosed and described in the above-incorporated by referenceapplication.

In one embodiment, the flow meter 575 may include a velocity sensor 591and speed of sound sensor 592 for measuring bulk velocity and speed ofsound of the fluid, respectively, up through the inner surface 506 ofthe casing string 505, which parameters are used in equations tocalculate flow rate and/or phase fractions of the fluid. As illustrated,the sensors 591 and 592 may be integrated in single flow sensor assembly(FSA) 593. In the alternative, sensors 591 and 592 may be separatesensors. The velocity sensor 591 and speed of sound sensor 592 of FSA593 may be similar to those described in commonly-owned U.S. Pat. No.6,354,147, entitled “Fluid Parameter Measurement in Pipes Using AcousticPressures”, issued Mar. 12, 2002 and incorporated herein by reference.

The flow meter 575 may also include combination pressure and temperature(P/T) sensors 514 and 516 around the outer surface 507 of the casingstring 505, the sensors 514 and 516 similar to those described in detailin commonly-owned U.S. Pat. No. 5,892,860, entitled “Multi-ParameterFiber Optic Sensor For Use In Harsh Environments”, issued Apr. 6, 1999and incorporated herein by reference. In the alternative, the pressureand temperature sensors may be separate from one another. Further, forsome embodiments, the flow meter 575 may utilize an optical differentialpressure sensor (not shown). The sensors 591, 592, 514, and/or 516 maybe attached to the casing string 505 using the methods and apparatusdescribed above in relation to attaching the sensors 30, 130, 230, 330,430 to the casing strings 5, 105, 205, 305, 405 of FIGS. 1–5.

Embodiments of the flow meter 575 may include various arrangements ofpressure sensors, temperature sensors, velocity sensors, and speed ofsound sensors. Accordingly, the flow meter 575 may include any suitablearrangement of sensors to measure differential pressure, temperature,bulk velocity of the mixture, and speed of sound in the mixture. Themethods and apparatus described herein may be applied to measureindividual component fractions and flow rates of a wide variety of fluidmixtures in a wide variety of applications. Multiple flow meters 575 maybe employed along the casing string 505 to measure the flow rate and/orphase fractions at various locations along the casing string 505.

The flow meter 575 may be configured to generate one or more signalsindicative of mixture density and speed of sound in the mixture. Forsome embodiments, a conventional densitometer (e.g., a nuclear fluiddensitometer) may be used to measure mixture density as illustrated inFIG. 3 of the above-incorporated application (Ser. No. 10/348,040) anddescribed therein. However, for other embodiments, mixture density maybe determined based on a measured differential pressure between twovertically displaced measurement points and a bulk velocity of the fluidmixture, also described in the above-incorporated application (Ser. No.10/348,040). The signal interface 560 is configured to determine flowrate and/or volumetric phase fractions based on the signals generated bythe flow meter 575, for example by using the equations described in theabove-incorporated application (Ser. No. 10/348,040).

Also depicted in FIG. 6 is a drill string 580. The drill string 580includes a tubular 582 having an earth removal member 581 attached toits lower end. The earth removal member 581 has passages 583 and 584therethrough for use in circulating drilling fluid F1 while drillinginto the formation 515 (see below).

In use, the flow meter 575 is placed within the casing string 505, e.g.,using the previously described technique of threaded connection to othercasing sections. The casing string 505 may also include casing sectionsincluding one or more of the sensor arrangements described above andshown in FIGS. 1–5 to simultaneously measure wellbore or formationparameters such as pressure, temperature, seismics, and/or acoustics,while also measuring flow rate and/or component fractions with one ormore flow meters 575.

The wellbore 510 is drilled to a first depth with a drill string (notshown). The drill string is then removed. The casing string 505 is thenlowered into the drilled-out wellbore 510, and physically alterablebonding material 520 may be introduced in the annulus and allowed tocure at hydrostatic conditions to set the casing string 505 permanentlywithin the wellbore 510, as described above in relation to FIG. 1.

The flow meter 575 is now permanently installed within the wellbore 510with the casing string 505 and is capable of measuring formation orwellbore parameters which allow calculation by the signal interface 560of fluid flow and component fractions present in the fluid flowingthrough the inner diameter of the casing string 505 during wellboreoperations. If employing additional sensors in, on, or within the casingstring 505 according to the embodiments of FIGS. 1–5, other formationand wellbore parameters may be simultaneously measured via pressure,temperature, seismic, or acoustic optical sensors, as described above.

Often, the wellbore 510 is drilled to a second depth within theformation 515. As shown in FIG. 6, the drill string 580 is inserted intothe casing string 505 and used to drill into the formation 515 to asecond depth. During the drilling process, it is customary to introducedrilling fluid F1 into the drill string 580. The drilling fluid F1 flowsdown through the drill string 580, as indicated by the arrows labeledF1, then out through the passages 583 and 584. After exiting thepassages 583 and 584, the drilling fluid F1 mingles with the particulatematter including cuttings produced from drilling into the earthformation 515, then carries the particulate matter including cuttings tothe surface 565 by the fluid mixture F2, which includes the drillingfluid F1 and the particulate matter. The fluid mixture F2 flows to thesurface 565 through an annulus between the outer diameter of the drillstring 580 and the inner surface 506 of the casing string 505, asindicated by the arrows labeled F2. The drilling fluid F1 is ordinarilyintroduced in order to clear the wellbore 510 of the cuttings and toease the path of the drill string 580 through the formation 515 duringthe drilling process.

While the fluid mixture F2 is circulating up through the annulus betweenthe drill string 580 and the casing string 505, the flow meter 575 maybe used to measure the flow rate of the fluid mixture F2 in real time.Furthermore, the flow meter 575 may be utilized to measure in real timethe component fractions of oil, water, mud, gas, and/or particulatematter including cuttings, flowing up through the annulus in the fluidmixture F2. Specifically, the optical sensors 591, 592, 514, and 516send the measured wellbore parameters up through the optical cable 555to the signal interface 560. The optical signal processing portion ofthe signal interface 560 calculates the flow rate and componentfractions of the fluid mixture F2, as described in theabove-incorporated application (Ser. No. 10/348,040) utilizing theequations and algorithms disclosed in the above-incorporatedapplication. This process is repeated for additional drill strings andcasing strings.

By utilizing the flow meter 575 to obtain real-time measurements whiledrilling, the composition of the drilling fluid F1 may be altered tooptimize drilling conditions, and the flow rate of the drilling fluid F1may be adjusted to provide the desired composition and/or flow rate ofthe fluid mixture F2. Additionally, the real-time measurements whiledrilling may prove helpful in indicating the amount of cuttings makingit to the surface 565 of the wellbore 510, specifically by measuring theamount of cuttings present in the fluid mixture F2 while it is flowingup through the annulus using the flow meter 575, then measuring theamount of cuttings present in the fluid exiting to the surface 565. Thecomposition and/or flow rate of the drilling fluid F1 may then beadjusted during the drilling process to ensure, for example, that thecuttings do not accumulate within the wellbore 510 and hinder the pathof the drill string 580 through the formation 515.

While the sensors 591, 592, 514, 516 are preferably disposed around theouter surface 507 of the casing string 505, it is within the scope ofthe invention for one or more of the sensors 591, 592, 514, 516 to belocated around the inner surface of the casing string 505 or embeddedwithin the casing string 505, as described above in relation to FIGS.1–5.

Measuring Flow While Drilling with Casing

FIG. 7 shows an alternate embodiment of the present invention. Mostcomponents are substantially the same in FIG. 7 (indicated by the “600”series) as the components in the “500” series of FIG. 6. This embodimentdiffers from the embodiment of FIG. 6 because the casing string 605 hasan earth removal member 621 operatively connected thereto. The earthremoval member 621 is used to remove portions of the formation 615 toform a wellbore 610. The casing string 605 is thus placed within thewellbore 610 while drilling into the formation 615.

To allow drilling fluid F1 circulation while drilling, the earth removalmember 621 includes passages 623 and 624 therethrough. The drillingfluid F1 is introduced into the casing string 605 while drilling throughthe formation 615, then exits through the passages 623 and 624. Cuttingsand other particulate matter then are swept into the drilling fluid F1to form the fluid mixture F2 which flows to the surface 665 via anannulus between the casing string 605 and the inner diameter of thewellbore 610. The flow meter 675 measures the flow rate and componentfractions of the fluid mixture F2, as described above, and sends theinformation to the signal interface 660 via the optical cable 655 forprocessing.

Once the casing string 605 is installed into place within the wellbore610, the sensors 691, 692, 614, 616 may be utilized to measure the flowrate and/or component fractions of the fluid mixture flowing up throughan annulus between the subsequent drill string (not shown) or thesubsequent casing string with the earth removal member attached thereto(not shown). Prior to drilling with the subsequent casing string ordrill string, the earth removal member 621 may be retrieved from thewellbore 610 after its removal from the casing string 605. In thealternative, the subsequent casing string or drill string may drillthrough the earth removal member 621 prior to drilling to a second depthwithin the formation 615. In addition to the flow meter 675, the casingstring 605 may include any of the embodiments described in FIGS. 1–5 toemploy other types of sensors for other types of measurements, such asseismic, acoustic, temperature, and/or pressure. These wellbore andformation parameters may be continuously measured after lowering thecasing string 605 into position within the wellbore 610, includingduring the drilling process with the subsequent drill string(s) orsubsequent casing string(s). In this manner, the flow meter 675 and/orother sensor arrangements of FIGS. 1–5 may be permanently employedwithin the wellbore 610 to obtain real time measurements during allwellbore operations, including the drilling and completion operationsdescribed at length above.

Several applications of the present invention are envisioned.Temperature, pressure, seismic, acoustic, and flow measurements may allbe utilized to adjust parameters while drilling with a drill string ordrilling with casing when the appropriate sensor(s) is placed on, in, orwithin the casing string 5, 105, 205, 305, 405, 505, or 605.Temperature, pressure, and flow measurements obtained in the presentinvention may aid in determining whether an underbalanced states hasbeen reached within the wellbore, permitting adjustment of wellboreconditions to prevent blowout.

Additional applications of the present invention are contemplated thatare specific to using one or more seismic sensors as the one or moreoptical sensors 30, 130, 230, 330, or 430 described in reference toFIGS. 1–5 and installing the seismic sensors with the casing string 5,105, 205, 305, 405 within the wellbore 10, 110, 210, 310, 410. Beforethe wellbore is drilled into the formation into which the casing stringis set, seismic data is often gathered from the surface to determineformation parameters prior to drilling the well. The seismicmeasurements from the surface may be calibrated by the seismicmeasurements obtained by the seismic sensor(s) installed with the casingstring.

Additionally, real time seismic measurements may be taken while drillinginto the formation during the completion operation. Specifically,imaging ahead of the earth removal member of the subsequent casingstring or drill string may aid in determining the direction in which theearth removal member should be steered (geosteering). Various parametersmay be adjusted by taking into account the real time seismicmeasurements obtained while drilling to troubleshoot as well as obtainmaximum production from the well. Pore pressure prediction is alsopossible using the real time seismic measurements during drilling.

Acoustic monitoring while drilling into the formation is also anadvantageous application of the present invention. The vibration of thedrill string, including the attached earth removal member, as well asother tools within the casing string may be monitored and adjusted.Acoustics relating to drilling fluids may be monitored with the presentinvention. The present invention allows monitoring of acoustic signalsfrom the wellbore having the casing string permanently disposed therein,or monitoring of acoustic signals from an adjacent wellbore.

In addition to improving seismic and acoustic monitoring of wellboreconditions during drilling, seismic and acoustic monitoring is possibleduring subsequent wellbore operations with the permanently deployedseismic and acoustic sensors with the casing string. During production,the same sensors which were employed to measure parameters during thecompletion operation may be utilized, as they are permanently installedwithin the wellbore. Therefore, microseismic monitoring as well as otheracoustic monitoring of production activities is possible with thepresent invention.

Another contemplated use for the present invention is use of thepermanently deployed seismic and/or acoustic sensor(s) for vertical orcrosswell seismic profiling. The profiling may be 2D, 3D, or 4D, orcontinuous microseismic monitoring such as microseismic profiling,depending upon the dimensions into which the seismic source emits theacoustic wave(s), as described above, with the fourth dimension beingtime. Crosswell seismic may be accomplished when the seismic source islocated in an adjacent wellbore by moving the seismic source toaccumulate a full image of the formation. Microsesimic monitoring allowsthe operator to detect, evaluate, and locate small fracture eventsrelated to production operations, such as those caused by the movementof hydrocarbon fluids or by the subsidence or compaction of theformation. These measurements are useful while drilling as well as afterdrilling, and during completion, production, intervention, and any otheroperations.

Although the above description of FIGS. 1–7 discusses cementing thecasing string having the optical sensor attached thereto, it is notnecessary in the present invention to cement the casing string withinthe wellbore. Pressure and temperature sensing with pressure andtemperature optical sensors does not require coupling to the formationor cement. Seismic optical sensors do require coupling to the formationto measure formation parameters, but this may be accomplished either bycementing the casing string to the formation or by placing the seismicsensor into significant contact with the wellbore, for example resultingfrom well deviation or corkscrewing. When cementing the casing stringwithin the formation in the above embodiments, the cement within theannulus may extend up to a portion of the casing string or to the upperend of the casing string or to the surface of the wellbore.

While the foregoing is directed to embodiments of the present invention,other and further embodiments of the invention may be devised withoutdeparting from the basic scope thereof, and the scope thereof isdetermined by the claims that follow.

1. An apparatus for permanently measuring wellbore or formationparameters, comprising: a casing string permanently located within awellbore by an alterable bonding material within an annulus between thecasing string and a surrounding formation, wherein at least a portion ofthe casing string comprises a protective pocket attached to an innersurface of the casing string; at least one sensor attached to the casingstring, the at least one sensor capable of measuring one or morewellbore or formation parameters, wherein the at least one sensor isattached to the casing string by location within the protective pocket.2. The apparatus of claim 1, wherein the protective pocket is disposedaround an inner surface of the casing string.
 3. The apparatus of claim1, wherein the one or more wellbore or formation parameters comprisespressure, temperature, seismic conditions, acoustics, fluid compositionwithin a formation, or combinations thereof.
 4. The apparatus of claim1, wherein the physically alterable bonding material is cement.
 5. Theapparatus of claim 1, wherein the at least one sensor comprises anoptical sensor.
 6. The apparatus of claim 1, wherein the at least onesensor includes a seismic sensor.
 7. The apparatus of claim 1, whereinthe at least one sensor includes a circumferential sensor disposedaround the inner surface of the casing.
 8. The apparatus of claim 1,wherein a plurality of optical sensors are attached to the casingstring.
 9. The apparatus of claim 8, wherein the plurality of opticalsensors attached to the casing string comprise a flow meter.
 10. Theapparatus of claim 8, wherein the one or more wellbore parameters areused to calculate flow rate of drilling fluid flowing through the casingstring, one or more component fractions of components present in thedrilling fluid, or combinations thereof.
 11. An apparatus forpermanently measuring wellbore or formation parameters, comprising: acasing string permanently located within a wellbore, wherein at least aportion of the casing string comprises a protective pocket attachedthereto; and at least one optical sensor attached to the casing string,the at least one optical sensor capable of measuring one or morewellbore or formation parameters, wherein the at least one opticalsensor is attached to the casing string by location within theprotective pocket, and wherein the protective pocket is disposed aroundthe casing string by a threaded connection.
 12. An apparatus forpermanently measuring wellbore or formation parameters, comprising: acasing string permanently located within a wellbore; at least oneoptical sensor located at least partially within a wall of the casingstring, the at least one optical sensor capable of measuring one or morewellbore or formation parameters; and an optical cable located withinthe wall of the casing string, the optical cable connecting the at leastone optical sensor to a signal interface.
 13. The apparatus of claim 12,wherein the at least one optical sensor is located completely within thewall of the casing string.
 14. The apparatus of claim 12, wherein theone or more wellbore or formation parameters comprises pressure,temperature, seismic conditions, acoustics, flow rate of drilling fluid,component fractions of components present in the drilling fluid, fluidcomposition within a formation, or combinations thereof.
 15. Theapparatus of claim 12, wherein a plurality of optical sensors arelocated at least partially within the wall of the casing string.
 16. Theapparatus of claim 15, wherein the plurality of optical sensors locatedat least partially within the wall of the casing string comprise a flowmeter capable of measuring flow rate or component fractions of fluidflowing within the casing string.
 17. A method of permanently monitoringwellbore or formation parameters, comprising: providing a casing stringhaving a protective pocket attached to an inner surface of the casingstring; locating the casing string within a wellbore; setting the casingstring permanently within the wellbore with a physically alterablebonding material; and monitoring a wellbore or formation parameter witha sensor attached to the casing string by location of the sensor withinthe protective pocket.
 18. The method of claim 17, wherein thephysically alterable bonding material is cement.
 19. The method of claim17, wherein the sensor includes a seismic sensor.
 20. An apparatus forpermanently measuring wellbore or formation parameters, comprising: acasing string permanently located within a wellbore, wherein the casingstring defines a substantially uniform inner diameter and asubstantially uniform outer diameter across its length; an alterablebonding material within an annulus between the casing string and asurrounding formation; and a sensor located at least partially within awall of the casing string between the inner and outer diameters, whereinthe sensor is capable of measuring wellbore or formation parameters. 21.The apparatus of claim 20, wherein the physically alterable bondingmaterial is cement.
 22. The apparatus of claim 20, wherein the sensor isattached to an outside of the casing string.
 23. The apparatus of claim20, wherein the sensor is attached to an inside of the casing string.24. The apparatus of claim 20, wherein the casing string comprises aprotective cover that the sensor is located within.